Systems and methods of removing stagnant liquid from a hydrocarbon well

ABSTRACT

The present invention is generally directed to systems and methods of removing liquids from hydrocarbon wells with liquid loading problems. More specifically, the present invention provides an intermittent gas lift system to remove stagnant liquid from hydrocarbon wells. The system includes a gas inlet port for gas to be injected into the well at a relatively low volume. The injected gas travels to a distal end of a lift tube inserted within a production tubing and then lifts or carries liquid up the lift tube to the surface.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119(e) to U.S.Provisional Patent Application Ser. No. 62/934,412 filed Nov. 12, 2019,which is incorporated herein in its entirety by reference.

FIELD

The present invention is generally directed to systems and methods ofremoving stagnant liquid from a hydrocarbon well with liquid loadingproblems. More specifically, the present invention is related to anintermittent gas lift system to remove stagnant liquid from liquidloaded hydrocarbon wellbores. The systems and methods of the presentinvention can be used with a well which includes a horizontal segmentand that produces oil, dry gas or a gas and condensate mixture.

BACKGROUND

The recent boom of oil and gas production in the United States hasresulted in a large increase in the number of horizontal wells. From2010 to 2017, the number of horizontal wells in the U.S. increased bynearly 220 percent and in 2017 there were over 234,000 productivehorizontal wells in the U.S. During the same period, the number ofvertical wells decreased by approximately 3 percent per year.

Unfortunately, horizontal wells generally have a relatively shortproduction life compared to vertical (or “conventional”) completions.Despite their large initial productivity, nearly 10 percent of thehorizontal wells in the U.S. become unproductive each year. The loss ofsuch a large percentage of horizontal wells annually results in a largeloss of revenue for operating companies and an increased ecologicalfootprint as more wells are drilled to replace wells that are out ofservice or plugged and abandoned (P&A).

Operating a horizontal well can be very difficult. One challenge iscaused by liquids in the reservoir that flow into and accumulate in thewell. Over time, the liquids can stagnant in the well and obstruct theflow of fluids, including natural gas or oil. Gas tends to readily flowin the well due to its low density. However, produced liquids, such ascondensate and water, tend to accumulate in the horizontal segment ofthe well due to gravity as water production increases and/or as downholepressure decreases. It is difficult to lift liquids from horizontalsections of a well. Thus, the liquids can form a “slug” andsignificantly impede or prevent the flow of hydrocarbons from thereservoir into the wellbore.

Initially, hydrocarbons and other liquids from the reservoir enter thewellbore at a velocity and pressure sufficient to transport liquids tothe surface. However, as pressure in the hydrocarbon reservoir near thewellbore drops, hydrocarbons entering the completion slow down. Theslower flow of hydrocarbons does not have the capacity to carry liquidsto surface. As liquids fall back in the vertical portion of the casingand tubing, the well may go from steady production to slug flow withinonly 3 to 4 years of operation. This slug flow pattern results in theaccumulation of liquids until the well can no longer flow, causing acontinuous accumulation of liquids or “liquid loading”. Liquid loadingleads to reductions in well production, intermittent flow, no-flow,mechanical equipment fatigue and failure, and accelerated pipecorrosion. These problems may cause production from the well to dropbelow profitable limits, making the well a candidate to be plugged andabandoned.

Liquid loading is a substantial problem in horizontal wells in shaleformations. Shale formations typically produce a large ratio of watercompared to other formations. Moreover, the low permeability of shaleformations reduces the velocity of hydrocarbons entering the wellborewhich decreases the ability of the gas to carry liquids to the surface.

To avoid liquid loading problems and extend the operating life of awell, lift methods must effectively remove fluids from the entirewellbore, including the horizontal sections. Unfortunately, noartificial lift method is currently available to remove liquids that arestagnant in the horizontal/lateral sections of a well.

One method of dealing with liquid loading is to use artificial lift (AL)systems. Some AL systems were developed over 30 years ago for verticalwells. Unfortunately, recent experimental and field observations haveindicated that AL systems are not as effective as expected in horizontalwells, or are cost prohibitive based on the required rig time needed forinstallation and equipment costs. Moreover, traditional AL systems havea poor performance record and fail sooner than expected, increasingoperational expenditures and reducing hydrocarbon recovery.

Another system for responding to liquid loading is the Dual Lift Systemproduced by Horizontal Lift Technologies and described in U.S. Pat. Nos.7,748,443 and 8,037,941 which are each incorporated herein by referencein their entireties. The Dual Lift System requires gas lift valves to beinstalled in a vertical section of a well. In addition, gases injectedinto the well as part of the treatment by the Dual Lift System cancontact the geologic formation and thus potentially causing formationdamage.

Accordingly, there is an unmet need for systems and methods of removingstagnant liquid from liquid loaded hydrocarbon wellbores that is costeffective and which does not include the deficiencies of known systems.

SUMMARY

One aspect of the present invention is to provide a system and a methodfor improving the production of a hydrocarbon well that is loaded withliquid by intermittently injecting compressed gas to the bottom of thewell to remove stagnant liquid from the well. In one embodiment, the gasis injected into the well at a relatively low rate. Specifically, in oneembodiment, the gas is injected into production tubing at the surface atless than approximately 100 ft³/min, or less than approximately 10ft³/min. In one embodiment, the gas is injected at a rate of betweenapproximately 0.1 ft³/min and approximately 5 ft³/min. Optionally, thegas may be compressed air.

Another aspect of the present invention is a novel system and method ofremoving stagnant liquid from a well without installing gas lift valvesin a vertical section of the well.

Still another aspect of the present invention is to provide a novelbacksweep lift configured to remove stagnant liquid from a well. Thebacksweep lift can be installed in a well without removing productiontubing previously installed in the well. In one embodiment, thebacksweep lift of the present invention operates with a single lift tubedeployed inside production tubing that has already been installed in thewell. In some embodiments, a pretreatment solution may optionally beinjected into the wellbore. The pretreatment solution is selected toreduce the surface tension of the stagnant liquid. In this manner, thepretreatment solution may enhance the ability of the gas to transportthe stagnant liquid to the surface.

One aspect of the present invention is to provide a backsweep liftconfigured to reach a horizontal section of a well and operateregardless of the volumetric gas fraction of the fluids coming from theformation.

Another aspect is to provide systems and methods for removing stagnantliquid from a hydrocarbon well and which prevent gases and pretreatmentsolutions that are injected into the well from escaping from theproduction tubing and contacting the geologic formation. In this manner,the systems and methods of the present invention facilitate continuousinflux of hydrocarbons into the wellbore from perforations in thegeologic formation. Additionally, the integrity of the geologicformation is not compromised or contaminated with injected gases and/orpretreatment solutions. In one embodiment, a backsweep lift of thepresent invention includes a downhole check valve interconnected to adistal end of the production tubing that is operable to prevent injectedgases and pretreatment solutions from escaping from the productiontubing.

One aspect of the present invention is an intermittent gas lift systemto remove stagnant liquid from a wellbore of a hydrocarbon well. The gaslift system comprises: (1) a downhole check valve interconnected to alower end of a production tubing positioned within the wellbore; (2) alift tube positioned within the production tubing which defines anannular space between an exterior surface of the lift tube and aninterior surface of the production tubing; and (3) a gas inlet portinterconnected to the production tubing at a wellhead portion of thehydrocarbon well such that gas injected through the gas inlet porttravels down the annular space to a distal end of the lift tube in ahorizontal section of the wellbore and then pushes liquid up the lifttube.

The downhole check valve prevents fluid from flowing out of the lowerend of the production tubing. When the gas is injected through the gasinlet port into the annular space, pressure in the lower portion of theproduction tubing increases and the downhole check valve closes toprohibit fluid from a hydrocarbon reservoir proximate to the lower endof the production tubing from flowing into the production tubing.Additionally, when the injection of gas through the gas inlet port intothe annular space stops, pressure in the lower portion of the productiontubing decreases and the downhole check valve opens to permit fluid froma hydrocarbon reservoir proximate to the lower end of production tubingto flow into the production tubing.

In one embodiment, the gas is injected through the gas inlet port at apressure of between approximately 100 psi and approximately 1,600 psi.Additionally, or alternatively, the gas can be injected through the gasinlet port at a rate of between approximately 0.1 ft³/min andapproximately 50 ft³/min.

In one embodiment, the distal end of the lift tube is positioned withinthe horizontal section of the wellbore. Optionally, the distal end ofthe lift tube is spaced upstream from the lower end of the productiontubing.

In one embodiment the gas lift system further comprises a solution inletport at the wellhead portion of the hydrocarbon well. The solution inletport can be connected to at least one of the production tubing and thelift tube. Accordingly, a pretreatment solution can be injected throughthe solution inlet port into at least one of the annular space andproduction tubing.

The gas lift system may optionally include a control system operable toautomatically start the injection of gas into the gas inlet port whenthe control system determines that data from a sensor indicates the wellis not producing hydrocarbons at a predetermined rate. The controlsystem generally includes instructions stored on a memory. Theinstructions cause the control system to send instructions to componentsof the gas lift system.

Optionally, the gas lift system includes a multiphase flowmeterinterconnected to the lift tube. In one embodiment, the multiphaseflowmeter is positioned proximate to the wellhead. Additionally, oralternatively, the multiphase flowmeter may be positioned between thewellhead portion and a three-phase separator.

In one embodiment, the gas lift system includes a pressure sensorpositioned within a horizontal section of the production tubing.

It is another aspect of the present invention to provide a method ofremoving stagnant liquid from a wellbore of a hydrocarbon well. Themethod generally includes, but is not limited to: (1) receiving firstdata from a sensor; (2) determining that the hydrocarbon well is notproducing hydrocarbons at a predetermined rate; (3) injecting a gas intoan annular space formed between an interior surface of a productiontubing positioned within the wellbore and an exterior surface of a lifttube positioned within the production tubing; (4) receiving second datafrom the sensor indicating that liquid flowing in the lift tube at thesurface includes some of the injected gas; and (5) stopping theinjection of gas into the annular space. In one embodiment, the firstdata received by the sensor includes one or more of a pressure measuredproximate to a bottom hole location and a pressure or a flow rate ofhydrocarbons from the wellbore. The pressure or flow rate of may bemeasured at or near the surface.

In one embodiment the method further includes injecting a pretreatmentsolution into the wellbore. The pretreatment solution is optionallyinjected into the wellbore before the gas is injected. Optionally, thepretreatment solution is injected through at least one of the productiontubing and the lift tube. The pretreatment solution can be injected intoat least one of the annular space and directly into the lift tube.

In one embodiment, the method includes injecting the gas through a gasinlet port at a pressure of between approximately 100 psi andapproximately 1,600 psi. Additionally, or alternatively, the method mayoptionally include injecting the gas through the gas inlet port at arate of between approximately 0.1 ft³/min and 50 ft³/min. In oneembodiment, the gas inlet port is interconnected to the productiontubing at a wellhead portion of the hydrocarbon well.

Optionally, the method includes interconnecting a downhole check valveto a lower end of the production tubing.

In one embodiment, the method comprises positioning the lift tube withinthe production tubing. The method may also include positioning the lifttube within the production tubing such that a distal end of the lifttube is spaced upstream from a lower end of the production tubing.

Optionally, the method can be performed by a control system. The controlsystem generally includes a non-transitory computer readable mediumcomprising a set of instructions stored thereon which, when executed bya processor of a control unit, cause the processor to execute the methodof removing stagnant liquid from a wellbore of a hydrocarbon well.

Another aspect is a non-transitory computer readable medium comprising aset of instructions stored thereon which, when executed by a processorof a control unit, cause the processor to execute a method of removingstagnant liquid from a wellbore of a hydrocarbon well. The instructionscomprise: (1) an instruction to receive first data from a sensor; (2) aninstruction to determine that the hydrocarbon well is not producinghydrocarbons at a predetermined rate; (3) an instruction to inject a gasinto an annular space formed between an interior surface of a productiontubing positioned within the wellbore and an exterior surface of a lifttube positioned within the production tubing; (4) an instruction toreceive second data from the sensor indicating that liquid flowing inthe lift tube at the surface includes some of the injected gas; and (5)an instruction to stop the injection of gas into the annular space.

In one embodiment, the first data includes one or more of a pressuremeasured proximate to a bottom hole location and a pressure or a flowrate of hydrocarbons from the wellbore measured at or near the surface.

Optionally, the instructions include an instruction to at least one of avalue and a pump to inject a pretreatment solution into the wellborebefore injecting the gas. The instruction causes the pretreatmentsolution to be injected into at least one of the production tubing andthe lift tube.

The Summary is neither intended nor should it be construed as beingrepresentative of the full extent and scope of the present disclosure.The present disclosure is set forth in various levels of detail in theSummary as well as in the attached drawings and the Detailed Descriptionand no limitation as to the scope of the present disclosure is intendedby either the inclusion or non-inclusion of elements, components, etc.in this Summary. Additional aspects of the present disclosure willbecome more clear from the Detailed Description, particularly when takentogether with the drawings.

The phrases “at least one,” “one or more,” “or,” and “and/or” areopen-ended expressions that are both conjunctive and disjunctive inoperation. For example, each of the expressions “at least one of A, Band C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “oneor more of A, B, or C,” “A, B, and/or C,” and “A, B, or C” means Aalone, B alone, C alone, A and B together, A and C together, B and Ctogether, or A, B and C together.

The term “a” or “an” entity refers to one or more of that entity. Assuch, the terms “a” (or “an”), “one or more,” and “at least one” can beused interchangeably herein. It is also to be noted that the terms“comprising,” “including,” and “having” can be used interchangeably.

Unless otherwise indicated, all numbers expressing quantities,dimensions, conditions, ratios, ranges, and so forth used in thespecification and claims are to be understood as being modified in allinstances by the term “about” or “approximately”. Accordingly, unlessotherwise indicated, all numbers expressing quantities, dimensions,conditions, ratios, ranges, and so forth used in the specification andclaims may be increased or decreased by approximately 5% to achievesatisfactory results. In addition, all ranges described herein may bereduced to any sub-range or portion of the range.

The use of “including,” “comprising,” or “having” and variations thereofherein is meant to encompass the items listed thereafter and equivalentsthereof as well as additional items. Accordingly, the terms “including,”“comprising,” or “having” and variations thereof can be usedinterchangeably herein.

It shall be understood that the term “means” as used herein shall begiven its broadest possible interpretation in accordance with 35 U.S.C.,Section 112(f). Accordingly, a claim incorporating the term “means”shall cover all structures, materials, or acts set forth herein, and allof the equivalents thereof. Further, the structures, materials, or actsand the equivalents thereof shall include all those described in theSummary, Brief Description of the Drawings, Detailed Description,Abstract, and Claims themselves.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of the specification, illustrate embodiments of the disclosedsystem and together with the general description of the disclosure givenabove and the detailed description of the drawings given below, serve toexplain the principles of the disclosed system(s) and device(s).

FIG. 1 is production schematic of a backsweep lift according to oneembodiment of the present invention installed on a hydrocarbon well witha horizontal section and depicting the surface equipment used inconjunction with the backsweep lift;

FIG. 2 is a cross-sectional view of the horizontal section of the welltaken along line 2-2 of FIG. 1 and illustrating a lift tube of thebacksweep lift positioned within previously installed production tubing;

FIG. 3 is a schematic view illustrating a liquid buildup phase of a wellin which the backsweep lift of FIG. 1 has been installed;

FIG. 4 is another schematic view illustrating gas being injected intothe well of FIG. 3;

FIG. 5 is a schematic view illustrating liquid being blown out of thewell of FIG. 3 during treatment of the well in accordance with thesystems and methods of embodiments of the present invention;

FIG. 6 is yet another schematic view of the well of FIG. 3 illustratingoperation of the well after the injection of gas ends;

FIG. 7 is a flow chart of a method of removing stagnant liquid from awellbore according to one embodiment of the present invention;

FIG. 8 is a graph illustrating the production and pressure profile forone operating cycle of a backsweep lift of one embodiment of the presentinvention;

FIG. 9 is another graph of a production and pressure profile during oneoperating cycle of the backsweep lift according to one embodiment; and

FIG. 10 is a graph of recovery factor versus Reynolds number fordifferent Eotvos numbers for one embodiment of the backsweep lift of thepresent invention.

The drawings are not necessarily to scale. In certain instances, detailsthat are not necessary for an understanding of the disclosure or thatrender other details difficult to perceive may have been omitted. Itshould be understood, of course, that the disclosure is not necessarilylimited to the embodiments illustrated herein. As will be appreciated,other embodiments are possible using, alone or in combination, one ormore of the features set forth above or described below. For example, itis contemplated that various features and devices shown and/or describedwith respect to one embodiment may be combined with or substituted forfeatures or devices of other embodiments regardless of whether or notsuch a combination or substitution is specifically shown or describedherein.

The following is a listing of components according to variousembodiments of the present disclosure, and as shown in the drawings:

Number Description  2 Geologic formation/hydrocarbon reservoir  4 Well 6 Wellhead  8 Wellbore 10 Vertical section 12 Horizontal section 14Fractures or perforations 16 Cement 20 Backsweep lift 22 Productioncasing 24 Casing vent line 26 Flow meter 28 Outer annular space 30Production tubing 32 Lower end of the production tubing 34 Downholecheck valve   35A Open position of downhole check valve   35B Closedposition of downhole check valve 36 Inner annular space 38 Lift tube 40Distal end of the lift tube 42 Production port 44 Gas inlet port 45 Gasline 46 Tank for compressed gas 48 Compressor 50 Gas flow meter 52Injected gas 54 Solution inlet port 56 Solution check valve 58 Pump 60Solution tank 62 Pretreatment solution 64 Three-phase separator 66Control system 68 Sensor   68A Surface sensor   68B Downhole sensor 70Method 72 Start 74 Received data from sensors 76 Determine whether wellis producing sufficient level of hydrocarbons 78 Inject a pretreatmentsolution into the wellbore 80 Inject a gas into the wellbore 82 Receivedata from a sensor 84 Determine whether to continue injection of the gasinto the wellbore 86 Stop injection of gas 88 Liquid in well   88ALiquid moving to the surface   88B Liquid moving downwardly 90 Pressuredrop in the horizontal inner annular space per unit length 92 Pressuredrop within the horizontal tubing per unit length 94 Pressure dropwithin the vertical tubing per unit length 96 Production (bbl) 98 Liquidrate (gpm) 100  Pressure at heel (psi) 102  Pressure at toe (psi) 104 Production (bbl) 106  Pressure gradient (psi/ft) 110  Eotvos number (Eo)of approximately 12 112  Eotvos number (Eo) of approximately 22 114 Eotvos number (Eo) of approximately 49

DETAILED DESCRIPTION

Referring now to FIGS. 1-2, a backsweep lift 20 according to oneembodiment of the present invention is generally illustrated. Thebacksweep lift 20 is shown interconnected to a well 4 in operablecommunication with a geologic formation 2. The well 4 generally includesa wellhead 6 at the surface and a wellbore 8 extending to the geologicformation. The wellbore includes a vertical section 10 and a generallyhorizontal section 12.

Production casing 22 within the wellbore 8 may optionally lined withcement 16. Perforations 14 formed through the production casing 22 andthe cement 16 provide a pathway for hydrocarbons, such as gas and/oroil, to flow from a hydrocarbon reservoir within the geologic formation2 and into the wellbore 8. In some embodiments, the geologic formationwill be fractured to increase the permeability and production ofhydrocarbons from the geologic formation.

Production tubing 30 is positioned within the production casing 22 anddefines an outer annular space 28 within the wellbore 8. The productiontubing 30 can be of any desired diameter. In one embodiment theproduction tubing 30 has an inner diameter of between approximately 2.0inches to approximately 3.5 inches, or between approximately 2.3 inchesand approximately 2.9 inches. The production tubing 30 is typicallyinstalled in the wellbore 8 before the backsweep lift 20 of the presentinvention is installed.

The backsweep lift 20 generally includes wellhead adaptations at thesurface and a bottomhole assembly. A production line or lift tube 38 ispositioned in the production tubing 30. The lift tube 38 extends fromthe surface down to the horizontal section 12 of the well 4. At thesurface, the lift tube 38 can be connected to a tank and/or athree-phase separator 64. The size and configuration of the three-phaseseparator 64 is determined based on an estimate maximum daily flow fromthe well. In one embodiment, a distal end 40 of the lift tube 38 ispositioned within the horizontal section 12 of the production tubing 30.Optionally, the distal end 40 of the lift tube 38 is spaced from a lowerend 32 of the production tubing 30.

In one embodiment, the lift tube 38 can be deployed inside productiontubing 30 that is already installed in the wellbore 8. For example, thelift tube 38 can be installed in the production tubing 30 withoutretrieving or extracting the production tubing 30 from the wellbore. Inthis manner, elements of the backsweep lift 20 of the present inventioncan be interconnected to (or installed in) the wellbore 8 faster, withless labor, and with less production downtime than prior art systemswhich require extraction of the production tubing from a wellbore. Forexample, some prior art systems require the installation of gas liftvalves in the production tubing. Additionally, because the backsweeplift 20 of embodiments of the present invention requires only one lifttube 38 to be introduced into the wellbore 8, the risks of helicalbuckling experienced in prior art systems that require installation oftwo lines of tubing into the wellbore are reduced. Further, the singlelift tube 38 used in one embodiment of the present disclosure reducesmaterial costs of the backsweep lift compared to some prior art systemswhich require two sections of tubing to be installed in the productiontubing.

The lift tube 38 has an outer diameter that is less than the innerdiameter of the production tubing 30. Accordingly, the lift tube 38defines a new or inner annular space 36 between an interior surface ofthe production tubing 30 and an exterior surface of the lift tube 38.Thus, gases and/or liquids injected from surface can flow through theinner annular space 36 down to the horizontal section 12.

Any suitable tubing may be used as the lift tube 38. Optionally, thelift tube 38 may be coiled tubing or “macaroni” tubing such as known tothose of skill in the art. The lift tube 38 may optionally include oneor more threaded joints. Alternatively, in one embodiment, the lift tube38 may be one continuous piece of material. In one embodiment, the lifttube 38 has an inner diameter of between approximately 0.2 inches andapproximately 1.0 inch or between approximately 0.4 inches andapproximately 0.8 inches. In another embodiment, the inner diameter ofthe lift tube 38 is between approximately 0.25 inches and approximately0.55 inches. Other dimensions and diameters are contemplated for thelift tube 38.

To operate with the existing production tubing 30, a downhole checkvalve 34 can be installed at the lower end 32 of the production tubing30. In one embodiment, the distal end 40 of the lift tube 38 is spacedfrom the downhole check valve. More specifically, the distal end 40 ofthe lift tube 38 may be positioned a predetermined distance uphole (orupstream) from the lower end 32 of the production tubing 30.

Check valves 34 that are suitable for use with the backsweep lift 20 ofthe present invention are known to those of skill in the art. Thedownhole check valve 34 is configured to permit stagnant fluids from theproduction tubing 30 and/or the production casing 22 to enter into thelift tube 38. However, the downhole check valve 34 is operable toprohibit the discharge of fluids and/or gas from the production tubing30 once a gas is injected at the surface at the wellhead 6.Specifically, in one embodiment, the downhole check valve 34 isconfigured to prevent gas injected from the surface from escaping fromthe inner annular space 36. In this manner, the production tubing 30works as a containment chamber. More specifically, the backsweep lift 20of the present invention can prevent or reduce the access of gasesand/or liquids injected into the inner annular space 36 from enteringthe outer annular space 28 and contacting the production casing 22 andflowing into the perforations 14. As will be appreciated by one of skillin the art, gases and liquids injected into the inner annular space 36to retrieve fluids that are stagnated in the horizontal section 12 ofthe well can contaminate or damage the geologic formation, alter theflow of hydrocarbons from the hydrocarbon reservoir, and cause otherissues in operation of the well. Preventing contact of injected gasesand liquids with the geologic formation is another benefit of thebacksweep lift of embodiments of the present disclosure compared to someof the prior systems, including the Dual Lift System of Horizontal lifttechnologies, which allow injected gases to contact the geologicformation.

At the wellhead 6, the backsweep lift 20 presents two inlet ports 44, 54and a production port 42. One of the inlet ports is a gas inlet port 44to inject compressed gas into the production tubing 30. The gas inletport 44 is connected to the production tubing 30. Accordingly, gasinjected through the gas inlet port 44 can flow down to the horizontalsection 12 along the inner annular space 36 between the productiontubing 30 and the lift tube 38.

In one embodiment, the gas inlet port 44 is used to inject gas at a lowvolumetric flow rate. The backsweep lift of the present invention caninject any suitable gas through the gas inlet port. In one embodimentcompressed air is injected through the gas inlet port. However, othergases or mixtures of gases may be used with the backsweep lift ofembodiments of the present invention.

The pressure at which the gas is injected through the gas inlet port 44is selected to cover the gravitational and frictional losses requiredfor the gas to flow to the bottom of the completion and push stagnantliquid along the lift tube 38 up to surface. The gas can be injectedthrough the gas inlet port 44 at a relatively high pressure. Forexample, in one embodiment, the gas is injected through the gas inletport at a pressure of between approximately 20 psi and approximately1,600 psi, or between approximately 500 psi and 900 psi. Additionally,or alternatively, in one embodiment of the present invention the gas isinjected at a pressure of less than approximately 100 psi. Morespecifically, in one embodiment, the pressure of the injected gas isbetween approximately 20 psi and approximately 70 psi.

In one embodiment, gas is injected through the gas inlet port 44 at arate of between approximately zero point one cubic feet per minute (0.1ft³/min) to approximately 100 cubic feet per minute (100 ft³/min). Inanother embodiment, the gas is injected at a rate of greater thanapproximately 0.1 ft³/min and less than approximately 50 ft³/min, orless than approximately 25 ft³/min. In one embodiment, the gas isinjected at a rate of between 0.1 ft³/min and approximately 5 ft³/min.One benefit of the low rate of gas injection is the reduction in losesdue to friction and thus reduction of the gas pressure required at thesurface.

The volume of gas required by the backsweep lift of the presentinvention is much less than used in current gas lift systems. Forexample, in one embodiment, the backsweep lift 20 of the presentinvention uses approximately 1/1000 as much gas as current gas liftsystems. Specifically, some known gas lift systems require gas to beinjected at much higher rates, such as greater than 500 ft³/min or up toone or more million cubic feet per day. By reducing the rate of gasinjected into the well compared to other gas lift systems, the backsweeplift 20 of embodiments of the present invention decreases both capitalexpenditures and operational expenditures for the well operator.Further, less energy is required to pump the gas into the backsweep liftof the present embodiment compared to some other known system, reducingfuel and/or electricity costs.

In one embodiment, the backsweep lift includes a tank 46 to supply thegas to the gas inlet port 44 by a gas line 45. The gas tank 46 has apredetermined volume. More specifically, the gas tank 46 is configuredto provide a volume of gas at sufficient pressure to cover thegravitational loss of the accumulated liquid column and also thefrictional losses of the gas as it travels from the inner annular space36 up the lift tube 38 back to the surface.

A pump or compressor 48 can be used to compress the gas in the tank 46.Optionally, a gas flow meter 50 may be installed between the tank 46 andthe gas inlet port 44. The gas flow meter 50 is configured to controlthe rate of gas injected into the gas inlet port 44. In one embodiment,the gas flow meter is a thermal mass flowmeter. Other suitable gas flowmeters that can be used with the backsweep lift 20 are known to those ofskill in the art.

In one embodiment, the gas flow meter 50 is operable to measure one ormore of the rate and the pressure at which the gas is injected into thegas inlet port 44. Additionally, or alternatively, the gas flow meter 50can be used to control the rate and/or pressure at which the gas isinjected through the gas inlet port 44 in such way that the flow insidethe production tubing 30 is at a predetermined rate as described herein.

The second inlet port 54 is optional and is for the injection of apretreatment solution into one or more of the production tubing 30and/or the lift tube 38. The solution inlet port 54 can be connected tothe well 4 through a surface check valve 56. The backsweep lift 20 caninclude one or more surface check valves 56 configured to permit theoptional introduction of the pretreatment solution into the innerannular space 36 and/or the lift tube 38 to pretreat stagnant liquid inthe system.

A pump 58 controls the rate at which the solution flows from a tank 60to one or more of the solution inlet ports 54A, 54B. Accordingly, thepretreatment solution can flow down to the horizontal section 12 of thewell to mix with liquids in the inner annular space 36 and the lift tube38.

The surface check valve 56 may also be configured to prohibit flowbackof recovered fluids and the pretreatment solution from the solutioninlet port 54. In one embodiment the second inlet port 54 is a one-wayvalve known to those of skill in the art.

In one embodiment, the solution inlet port 54A is configured to injectthe pretreatment solution into the inner annular space 36 between theproduction tubing 30 and the lift tube 38. Additionally, oralternatively, the solution inlet port 54B can optionally be configuredto inject the pretreatment solution into the lift tube 38. In thismanner, the pretreatment solution can flow from the surface down thelift tube 38 and to the distal end 40 of the lift tube.

The pretreatment solution 62 is selected to increase the surface tensionbetween air (or another gas) and liquid. More specifically, thecomposition of the pretreatment solution 62 is selected to improve thelifting efficiency of the gas injected at surface such that more liquidis lifted to the surface.

In one embodiment, the pretreatment solution 62 is an electrolyticantisurfactant solution. The electrolytic antisurfactant solution canoptionally include an antisurfactant agent to increase the surfacetension between air (or another gas) and liquid. In one embodiment, thesolution 62 can include one or more of an electrolytic or a saccharidic.In another embodiment, the pretreatment solution is a sodium chloridesolution. In still another embodiment, the pretreatment solutionincludes a sucrose solution. Additionally, or alternatively, thesolution can optionally have a high antisurfactant concentration. In oneembodiment, the solution 62 may optionally include phosphorous. Testingof various solutions with the backsweep lift of the present inventionindicates that saccharidic antisurfactants that include phosphorousincrease the volume of liquids (such as water) removed by at leastapproximately 20 percent compared to pure water that has not been mixedwith a pretreatment solution 62. Additionally, testing indicates that asaccharidic-phosphoric anti-surfactant pretreatment solution improvesefficiency compared to other pretreatment solutions that were tested.More specifically, a saccharidic-phosphoric anti-surfactant pretreatmentsolution successfully achieved an increase in production at a volumethat is 1/100 less than the volume required by an electrolyticsurfactant or a simple saccharidic surfactant.

The backsweep lift 20 of one embodiment of the present invention canoptionally include a control system 66. The control system generallyincludes a processor, a memory, a bus, and instructions stored in thememory. The instructions are operable to control one or more elements ofthe backsweep lift 20. More specifically, in one embodiment, the controlsystem 66 is in communication with and can send instructions to activateelements of the backsweep lift. For example, the control system canautomatically begin the injection of gas into the well 4 to removestagnant liquid from the wellbore 8. In one embodiment, the controlsystem 66 can send a signal to activate or deactivate the compressor 48.Additionally, or alternatively, the control system may send a signal toopen or close a valve associated with the tank 46. In this manner, thecontrol system can automatically inject gas into the well 4 to liftstagnant liquid from the wellbore. The control system may also controlthe rate at which the gas is injected by sending instructions to the gasflow meter 50. In one embodiment, the control system can optionally senda signal to the solution check valve 56 to permit the injection of apretreatment solution into the well 4.

Suitable control systems are known to those of skill in the art. In oneembodiment the control system is a personal computer. In anotherembodiment, the control system 66 is a personal computer running the MSWindows operating system. Optionally, the control system 66 can be asmart phone, a tablet computer, a laptop computer, and similar computingdevices. In one embodiment, the control system 66 is a data processingsystem which includes one or more of, but is not limited to: at leastone input device (e.g. a keyboard, mouse, or touch-screen); an outputdevice (e.g. a display, a speaker); a graphics card; a communicationdevice (e.g. an Ethernet card or wireless communication device);permanent memory (such as a hard drive); temporary memory (for example,random access memory); computer instructions stored in the permanentmemory and/or the temporary memory, and a processor. The control system66 may be any programmable logic controller (PLC). One example of asuitable PLC is a Controllogix PLC produced by Rockwell Automation,Inc., although other PLCs are contemplated for use with embodiments ofthe present invention.

In one embodiment, the backsweep lift 20 further comprises one or moresensors 68. The sensors 68 are operable to determine a pressure of gasat one or more locations of the well. Additionally, or alternatively,the sensors 68 can measure the volume or flow rate of a fluid, such asgas, at one or more locations.

Suitable sensors that can measure flow rates and the pressure of gas areknown to those of skill in the art. The sensors 68 may include one ormore of a helical bourdon tube gauge, a strain gauge, a quartz crystalgauge, a surface readout gauge, and a digital memory gauge.Additionally, or alternatively, the sensor 68 may be one or more of aspinner flowmeter, a torque flowmeter, and a cross-correlationflowmeters.

In one embodiment, a sensor 68A is positioned at the wellhead 6. Thesensor 68A may be interconnected to the lift tube 38 at the surface. Inone embodiment, the sensor 68A is a multiphase flowmeter. Suitablemultiphase flowmeters are known to those of skill in the art.

Optionally, a sensor 68B can be interconnected to the lift tube 38 inthe wellbore 8, such as within the horizontal section 12. In oneembodiment, the sensor 68B is a pressure sensor. The pressure sensor 68Bis optionally positioned within the production tubing 30.

The control system 66 may be in communication with one or more of thesensors 68. Additionally, or alternatively, the control system 66 mayalso be in communication with the flow meters 26, 50, the compressor 48,the pump 58, and the check valves 56A, 56B. In one embodiment, thecontrol system 66 can automatically send a signal to a valve to injectgas from the tank 46 into the wellbore in response to data from asensor. For example, in one embodiment, the control system 66 canmonitor the flow rate and/or pressure of gas at the wellhead 6, such aswith data from sensor 68A. When one or more of the flow rate and thepressure drop below a predetermined level, or drop by a predeterminedamount or a predetermined percent, the control system 66 can send asignal to inject gas into the wellbore to lift stagnant liquid from thewell. Optionally, the control system 66 can send a signal to inject apretreatment solution into the wellbore.

The control system 66 can control the injection of gas and/orpretreatment solution into the well based on one or more of the pressureof gas at the surface and the volume of gas flowing through the lifttube 38. More specifically, the control system 66 can control theduration and frequency of the fluid loading in the well and also theperiods during which compressed gas and pretreatment solutions areinjected into the well. In this manner, the gas-to-liquid removalefficiency of the backsweep lift can be optimized resulting in theremoval of more liquid per cycle, lower expenses due to operation of thegas compressor 48, and improved production of hydrocarbons from thewell.

Referring now to FIGS. 3-6, operation of the backsweep lift 20 of oneembodiment of the present disclosure is generally illustrated. FIG. 3generally illustrates a liquid buildup phase. During the liquid buildupphase, hydrocarbon production through the production tubing 30 willgenerally decrease over time. The duration of the liquid buildup phaseis determined by the flowrate incoming from the formation and thepressure loses registered in the perforations 14. The flowrate can becalculated from the inflow performance relationship if the permeabilityand flowing radius of the formation are known. The pressure drops in theformation are generally related to the type of cement and size andcharge type of the perforating gun used. Otherwise, the pressure dropcan be calculated from the time it takes for the formation to accumulatea certain volume of liquid on the lift tube 38. This volume isdetermined from the geometrical specifications of the completion and thepressure reached on the lift tube which is measured by the pressuretransducer located in the toe (element 68B of FIG. 1).

As fluids 88 interfere with operation of the well 4, such as byobstructing or impeding the flow of hydrocarbons to the surface, apretreatment solution 62 can optionally be injected through the solutioninlet port 54 into the wellbore, as generally illustrated in FIG. 3. Inone embodiment the pretreatment solution 62 is injected into theproduction tubing 30 and the inner annular space 36. The pretreatmentsolution can enter into the lift tube through the distal end 40 of thelift tube 38 in the horizontal section 12. Additionally, oralternatively, the pretreatment solution can be injected directly intothe lift tube 38.

The pretreatment solution 62 flows in the inner annular space 36 and/orthe lift tube 38 from the surface to the horizontal section 12 and thelower end 32 of the production tubing 30. As the pretreatment solutionmixes with liquids 88 in the wellbore, including within the innerannular space 36, the surface tension of the stagnant liquid in thehorizontal section 12 and within the lift tube 38 is increased toimprove the recovery factor of the cycle. The reduction of the surfacetension determines the shape and dimensions of the gas slug produced bythe gas injected through the gas inlet port 44. By decreasing thesurface tension of the stagnant liquid, the injected gas can form abubble of a larger diameter. The larger diameter of the gas bubbleimproves the ability of the gas bubble to lift liquid as the gas bubbleflows through the stagnant liquid.

As the liquid phase accumulates in the production casing 22 and theproduction tubing 30, the downhole check valve 34 at the end of theproduction tubing 30 is open 35A and allows the entrance of fluids (bothgas and liquid) from the reservoir into the production tubing 30 andinto the lift tube 38. However, the downhole check valve 34 prevents thepretreatment solution from flowing out of the production tubing and intothe outer annular space 28.

The downhole check valve 34 remains open 35A since the pressure insidethe lift tube 38 and production tubing 30 is lower than the pressurewithin the production casing 22. The lower pressure on the inner annularspace 36 between the production tubing 30 and the lift tube 38 allowsthe pretreatment solution to enter the production tubing.

Referring now to FIG. 4, once a desired level of liquid is reached inthe lift tube 38, gas 52 is injected from the surface through the gasinlet port 44. The injected gas 52 flows down to the level of theliquids along the inner annular space 36 between the production tubing30 and the lift tube 38. In one embodiment, the control system 66 candetermine a desired column of liquid has accumulated in the verticalsection 10 of the wellbore 8 based on data from the sensor 68B(illustrated in FIG. 1) near the toe of the well.

In one embodiment, the flow rate at which the liquid travels will beproportional to the gas injection rate and the ratio between thecross-sectional areas of the gas injection line 45 and the inner annularspace 36. Any type of gas may be injected into the well by the backsweeplift 20. For example, the injected gas 52 may be a natural gas oranother hydrocarbon. In one embodiment, the injected gas 52 is producedby the well 4. Optionally, an inert gas is injected into the well.Additionally, or alternatively, the gas may be nonflammable. The gas maybe a combination of two or more gases.

In one embodiment, the injected gas 52 is air. Although a gas 52 otherthan air may be injected into the wellbore in one embodiment of thepresent invention, no experimental or theoretical basis suggests thatthe use of a gas different than common air will improve results. Morespecifically, tests indicate that the use of air reduces inefficienciesdue to its lower compressibility. In addition, the use of air as theinjected gas 52 reduces operational costs due to its availability.

As the injected gas 52 travels down the inner annular space 36, theinjected gas contacts the trapped or stagnant liquid 88, increasing thepressure in the production tubing 30 and closing 35B the downhole checkvalve 34. With the downhole check valve closed 35B, no more fluids canenter the production tubing 30 from the hydrocarbon reservoir.Additionally, the downhole check valve 34 prevents the injected gas 52and the pretreatment solution 62 from entering the outer annular space28 and accessing the production casing 22 and/or the hydrocarbonreservoir 2. The injected gas causes the pressure in the productiontubing 30 to increase to a level that is greater than the pressurewithin the lift tube 38.

Referring now to FIG. 5, due to the pressure differential between theinner annular space 36 (which is at a high pressure) and the lift tube38 (which is at a low pressure), the injected gas 52 pushes the stagnantliquid 88 into the lift tube 38 and up to surface. In this manner, theinjected gas 52 commences a production stage of the cycle. For example,the injected gas will travel from the gas inlet port 44 through theinner annular space 36 and down to the distal end 40 of the lift tube38. The injected gas will then enter the lift tube 38 and travel back upto the surface within the lift tube, pushing or carrying stagnant liquid88 to the surface as the injected gas 52 rises and completes the cycle.

Referring now to FIG. 6, after a predetermined volume of liquid isrecovered at the surface, the injection of gas is stopped. This volumecan be calculated as a function of the maximum pressure available insidethe production casing 22 and either the productivity index of the wellor the characteristics of the reservoir (such as one or more ofpermeability, flow area, and viscosity of the produced fluids). Thesetwo inputs are used along with the internal diameter of the productioncasing 22 to calculate the maximum height of the column of liquid thatwill accumulate inside the completion. The length of this column, alongwith the horizontal distance at which the downhole check valve 34 isinstalled inside the production tubing 30, determines the volumeexpected at the surface per production cycle, as well as the timerequired to load the backsweep lift 20. If the hydrostatic pressure ofthe accumulated column plus the expected frictional loses caused by thecombination of the dimensions of the completion, the properties of thefluid and the flowrate of the injected gas result in a larger pressurerequirement than that available from the gas injection system 46 atsurface, then the distance from the surface to the location of the checkvalve in the tubing, may be reduced by repositioning the downhole checkvalve 34. Additionally, or alternatively, the gas injection system ofthe backsweep lift 20 can be enlarged, such as by increasing the volumeof the tank 46 and/or the capacity of the compressor 48.

In one embodiment, when the injected gas 52 starts to flow out at thesurface with the liquids 88, the injection of gas through the gas inletport 44 may be stopped. In one embodiment, the control system 66 canautomatically stop the injection of gas when injected gas is detected inthe liquid 88 flowing through the lift tube 38 at the surface. In oneembodiment, the mixture of injected gas 52 in the liquid 88 can bedetected by a sensor, such as a multiphase flow meter 68A locateddownstream from the three-phase separator 64. As the tail-end of theliquid slug reaches the sensor 68A, variations in the density of thefluid as well as intermittent flow readings are recorded by the sensor.The peak values of the density will be close to that of the liquid,while the lower values will resemble those of water. This behaviorindicates that the nose or beginning of the gas slug has reachedsurface.

The liquid slug will travel at a changing velocity that is dependentupon the position of the liquid slug within the well and the welltrajectory. More specifically, the liquid slug generally travels at aslower velocity in the horizontal section 12 until the gas slug reachesthe vertical section 10 of the wellbore 8. Once the gas slug reaches thevertical section, the flowrate of the phases will accelerate due to theenergy accumulated by the gas phase and the reduction of the size of theliquid column as the amount of liquid above the gas slug decreases as itis pushed out of the vertical section 10 of the well.

When the injection of gas into the gas inlet port 44 stops, the loss ofpressure in the inner annular space 36 and the lift tube 38 results inthe fallback 88B of fluids 88 remaining in the vertical section 10 ofthe lift tube. The decrease of pressure in the production tubing 30 alsoallows the downhole check valve 34 to reopen 35A as illustrated in FIG.6. When the downhole check valve 34 is in the open position 35A, morefluid 88 from the hydrocarbon reservoir 2 can enter the productiontubing 30 and the cycle restarts.

The time required to reach this point in the operation cycle of thebacksweep lift 20 can be calculated from the gas injection rate, thevolume of the inner annular space 36, and the volume of lift tube 38.This can be used as an input for the control system 66 to shut of theinjection of gas through the gas inlet port 44. For example, the controlsystem 66 can close the gas flow meter 50. In one embodiment, thecontrol system 66 includes a machine learning algorithm and can useprevious cycles to improve the determination of the build-up time andthe gas injection time to further improve efficiency.

Referring now to FIG. 7, a method 70 of one embodiment of the presentinvention for removing stagnant liquid from a wellbore 8 is generallyillustrated. While a general order of operations of the method 70 isshown in FIG. 7, it will be understood by one of skill in the art thatthe method 70 can include more or fewer operations and can arrange theorder of the operations differently than those shown in FIG. 7. Althoughthe operations of the method may be described sequentially, many of theoperations may in fact be performed in parallel or concurrently.Generally, the method 70 starts with a start operation 72 and can loopone or more times. The method 70 can be executed as a set ofcomputer-executable instructions executed by a computer system andencoded or stored on a computer readable medium. One example of thecomputer system may include, for example, the control system 66. Anexample of the computer readable medium may include, but is not limitedto, a memory of the control system 66. Hereinafter, the method 70 shallbe explained with reference to the backsweep lift 20 and componentsdescribed in conjunction with FIGS. 1-6.

At operation 74, the control system 66 receives data from one or moresensors 26, 68 associated with the well. The sensors may indicate that aflow rate of the well has decreased by a predetermined amount or apredetermined percent. Additionally, or alternatively, the sensors mayrecord pressure at one or more positions of the well.

At operation 76, the control system 66 can determine whether the well isproducing hydrocarbons at a sufficient level or has become loaded withstagnant liquid. Specifically, the control system can determine if thewell is or is not producing hydrocarbons at a predetermined level orrate. The data from the sensor may also indicate that the pressure atthe surface is below a predetermined amount, has decreased by apredetermined amount, and/or has decreased by a predeterminedpercentage. When the control system determines the well is producinghydrocarbons at or above a predetermined level, method 70 loops YES tooperation 74. In one embodiment, the predetermined level is associatedwith at least one of a flow rate and a pressure. Optionally, thepressure can be above approximately 5 PSI or above approximately 100PSI. Alternatively, when the control system 66 determines the well isproducing hydrocarbons below the predetermined level, method 70continues NO to operation 78. In one embodiment, the control system willdetermine the well is producing hydrocarbons below the predeterminedlevel when the pressure is less that approximately 25 PSI, or less thanapproximately 5 PSI. Additionally, or alternatively, the control systemcan determine the well is producing hydrocarbons below the predeterminedlevel when the flow rate of hydrocarbons at the surface is less thatapproximately 25 cubic feet per minutes (CFM) or less than approximately5 CFM.

In operation 78 the control system can optionally inject a pretreatmentsolution into the wellbore. The control system 66 can send a signal toopen a valve associated with the solution inlet port 54. Optionally, thecontrol system 66 will also activate the pump 58.

In operation 80, the control system can send a signal to begin theinjection of gas into the wellbore 8 through the gas inlet port 44. Inone embodiment, the control system will send the signal to a valveassociated with the tank 46 and/or the gas inlet port 44 to start theinjection of gas into the wellbore. Optionally, the control system 66can send a signal to the gas flow meter 50 to control the rate and/orpressure of the gas injected. The control system 66 may also activatethe compressor 48 if necessary.

In operation 82 the control system 66 can receive data from a sensorindicating that liquid is recovered from the lift tube 38 at thesurface. The control system may also receive data on the volume ofliquid recovered from the lift tube. Additionally, or alternatively, thecontrol system 66 may optionally receive data indicating that gasinjected into the wellbore through the gas inlet port 44 is beingrecovered from the lift tube 38 at the surface. In one embodiment, thecontrol system 66 receives the data from one or more of the flow meter26, sensor 68A, and a sensor associated with the three-phase separator64.

In operation 84 the control system can determine whether the injectionof gas into the wellbore should continue. More specifically, after apredetermined amount of liquid is recovered at the surface, the controlsystem 66 can send a signal to stop the injection of gas into thewellbore in operation 86. The predetermined amount of liquid can bebetween approximately 1 barrel to approximately 50 barrels.

Additionally, or alternatively, the control system can optionally sendthe signal after a predetermined period of time has elapsed from whenthe injection of gas started in operation 80. For example, the controlsystem 66 may send a signal to stop the injection of gas afterapproximately 30 minutes, after 1 hour, or after 2 hours.

In one embodiment, the control system can stop the injection of gasafter a predetermined volume of gas has been injected into the well. Forexample, the control system can stop the injection of gas afterapproximately 10,000 ft³ of gas has been injected. Alternatively, thecontrol system can send the signal to stop the injection of gas afterapproximately 30,000 ft³, or approximately 100,000 ft³ of gas has beeninjected. When the control system determines the injection of gas shouldstop, the method 70 continues NO to operation 86 and then loops back tooperation 74 to begin another cycle of method 70. When the controlsystem 66 determines the injection of gas should continue, the methodloops back YES to operation 78 and the control system can optionallyinject more solution and/or gas into the wellbore 8.

EXAMPLES

The backsweep lift 20 of one embodiment of the present invention wastested in a low-pressure loop that includes a vertical section and ahorizontal section. The loop was instrumented using gas mass flow metersand liquid flow meters to control the gas supplied to the backsweep liftand measure the liquids produced respectively. The frictional andgravitational pressure drops were measured using digital transducersinstalled across the horizontal and vertical sections of the loop. Allthe data was logged using a digital unit connected to each of themeasuring devices, sampling the information at a rate of one take per0.08 seconds for each measuring device. The data obtained was used tomodel the operation of the backsweep lift 20 and predict the volumes ofliquid removed from the completion and the injected gas-to-recoveredliquid efficiency.

The performance of the backsweep lift of the present invention relies onthe optimization of the sweeping effect of the injected gas (known as aTaylor bubble) as the injected gas pushes the liquids through the lifttube 38 to the surface. Generally, the relatively small diameter of thelift tube 38 improves the ability of the Taylor bubble formed by theinjected gas to push liquid to the surface. The results are presented interms of the Eötvös number (Eo) and the Reynolds number of the injectedgas (Re). The Eötvös number relates the gravitational forces acting onthe gas-liquid interface to the surface tension forces present betweenthe two immiscible fluids and it is a function of liquid and gasdensity, surface tension between gas and liquid, and internal diameter.The Reynolds number measures the ratio of inertial to viscous forces forthe Taylor bubble neglecting the film thickness.

It has been observed that the raise velocity of the gas (given by aFroude number) for the same liquid decreased as the Eötvös numberdecreased. The Froude number relates the inertial to the gravitationalforces and measures the capacity of a body to displace over the surfaceof a liquid. In the case of multiphase flow, the Froude number addressesthe ease with which one phase slides over another. Studies have shownthat in the case of water, for Eo<70, the displacement of the Taylorbubble only depends on the surface tension. This occurs for a Mortonnumber (Mo) (which relates the viscous to the surface tension forces)below 2E10-8 and to Eo numbers smaller than 50.

Other studies have shown that for a surface tension dominated area of aTaylor bubble, the rise velocity of the Taylor bubble is related to acertain shape of the nose and the diameter of the gas slug. As the Eonumber of the Taylor bubble decreases, the roundness of the nose of theTaylor bubble changes towards a sharper angle. In the same sense, theclearance between the Taylor bubble and an interior surface of the lifttube 38 is reduced. This restricts the flow of the liquid film downwardsas it enters the space with a sharper angle change, due to a moredrastic flow area change.

When the Eo number is approximately 4.23, a zone of recirculation existsat the nose of the Taylor bubble which reduces a downward streamline ofthe liquid. Accordingly, when the Eo number is approximately 4.23, theTaylor bubble has little or no ability to rise in the liquid and accessof fluids past the Taylor bubble is practically prevented, forbiddingthe gas phase to flow through the liquid column of the lift tube 38.

FIG. 8 is a graph showing the performance of the system for a line withan inner diameter of approximately 0.375 inches with air injected atapproximately 45 psi at a rate of approximately 5 standard cubic feetper minute (scf/m). The logging device was set at a sampling rate of0.08 seconds, therefore each timestep represents a 0.08 second lapse.The air injection starts around the timestep 280 (or 23.2 seconds afterthe data logging unit started taking data). Line 90 comprises closedcircles and represents pressure drop per unit length (dP/dL) in thehorizontal annular space or annulus. Line 92 includes X's and representsdP/dL in the horizontal tubing. The dp/dL in the vertical tubing isrepresented by line 94 comprising triangles. Finally, production isrepresented by line 96 which includes squares.

At timestep 280, the fluids begin to move, registering an increase inthe pressure drop per unit length (dP/dL), presented in the lines 90,92, and 94. The difference between the magnitude of the dP/dL of thehorizontal tubing 92 and the vertical tubing 94 is due to the action ofgravity against the flow in the vertical tubing. The difference betweenthe dP/dL of the horizontal tubing 92 and the annulus 90 is due to thelower velocity occurring in the annulus.

At about 10 seconds after starting the injection of gas into thewellbore, the cumulative production (line 96) starts to increase,showing an inclined straight line that maintains up to about 40 secondsafter the injection of air started (timestep 800). While the gas slugwas still in the horizontal section, the frictional pressure drop inboth the horizontal section of tubing (line 92) and the vertical sectionof the tubing (line 94) remains generally constant which is a product ofa constant flowing velocity. This is caused by the constant hydrostaticpressure on the vertical section, which balances the pressure of the gasgenerating the flow at constant rate. Once the gas cleared thehorizontal section and started to travel up through the vertical tubing,the hydrostatic pressure diminished, allowing an acceleration of theflow of the two phases, and so an exponential increase of the frictionalpressure drop was recorded at approximately the 800th timestep or about32 seconds after the cycle started.

It is hypothesized that the flow behaves as one big liquid slug, beingpushed by a gas slug, which reflects the idea of a piston effect orplowing of the Taylor bubble as it travels along the production line.The undulations observed in the frictional pressure drop are a productof the slugging pattern that took place once the front of the Taylorbubble cleared the production line. Because the injection of gas intothe system was cut once the Taylor bubble cleared the production line,the pressure of the gas decreased, which explains the declining trend ofthe pressure drop during the slug flow. The frictional pressure drop inthe annulus (line 90) was several times lower than those seen in thehorizontal and vertical sections of the tubing, since thecross-sectional area of the annular space was much larger than thecross-sectional area of the tubing.

FIG. 9 is another graph illustrating a production and a pressure profilefor one operating cycle of the backsweep lift of one embodiment of thepresent invention with a lift tube 38 having an interior diameter ofapproximately 0.75 inches. During the cycle, air was injected atapproximately 40 psi at a rate of approximately 0.1 scf/min. As shown inFIG. 9, the air injection started when the pressure at the toe 102(represented with hollow circle data points) reached 6 psi, about 18seconds after starting to record the data. This was the largest pressurethat the pump could provide to the experimental loop, therefore themaximum column of accumulated liquid possible. As the gas pressure inthe system starts to increase, the liquid pressure in the system startsto decrease, which is observed at about 19 seconds, as the pressuregradient or pressure drop per unit length in the system 106 (indicatedby the hollow triangle data points) starts to reduce from the expectedvalue of approximately 45 psi/ft (which is the water pressure gradientfor that temperature). The pressure at the heel 100 (indicated by X datapoints) (read by a transducer above the column of water) starts toincrease, which indicates the beginning of liquid flow past this point.After about 50 seconds of operation, the pressure drop per unit length(pressure gradient 106, which is represented by triangles) reaches itslowest values, indicating the compensation of the gravity of the columnwith the pressure supplied by the gas. From here to approximately the105th second, the pressure gradient line 106 presents approximatelysteady state conditions, indicating the existence of single-phase flow.From approximately 50 seconds to approximately 105 seconds, the pressurelines 100 and 102 show approximately steady state behavior as well, andthe readings from the liquid flowmeter 98 (indicated by hollowdiamonds), remain generally constant as well. During the experiments, nogas was observed in the vertical section up to this point.

Once the gas slug reached the vertical section (after about 110seconds), the pressure (100, 102) in the vertical lines started todecrease, while the liquid rate 98 accelerated. This shows theacceleration of the gas slug due to the reduction of the size of theliquid column on top of the gas slug. From this point on, thehydrostatic pressure and the gas pressure do not balance anymore,allowing the gas slug to flow faster. For this same reason, the trend ofthe production line 104 (represented by hollow squares) increases andthe pressure drop per unit length 106 increases dramatically as thefluids start to travel on a slug flow pattern and then an annular flowpattern, as the gas accelerates due to a smaller liquid column on thevertical section of the completion. In the first slug flow pattern, theliquids arrive at the surface as intermittent pulses of gas and liquidas the gas clears the remaining liquids in the vertical section. In thesecond annular flow pattern, the liquids flow to surface along the pipein a film covering the wall, while the gas travels at high speed throughthe center of the pipe. At this moment the gas valve was shut down torepeat the cycle.

The experimental results prove the piston-like behavior of the gasduring the early times of the operation. As the Taylor bubble travelsalong the production line, before reaching the vertical section, nearly80% of the production of the stagnant liquid occurs in single phaseform. The remaining 20% of the production arrives in intermittent slugsand annular flow. The undulations observed in the frictional pressuredrop are a product of the slugging pattern that took place once thefront of the Taylor bubble reached the vertical section of theproduction line. When the Taylor bubble cleared the production line,injection of gas into the system was cut and the pressure of the gasdecreased. This explains the declining trend of the pressure drop duringthe slug flow.

To observe the impact of the flowrate and the Eotvos number on theRecovery Factor, the experimental protocol was repeated several timesfor each test slot according to the experimental matrix. Each of thedata points presented in FIGS. 8 and 9 represents the averaged resultsof eight operating cycles held at the same gas flowrate for tubing withthe same inner diameter.

Referring now to FIG. 10, it can be observed that the lower the Reynoldsnumber of the injected gas, the larger the recovery factor of thesystem. Most probably, the lower turbulence seen at low flowrates allowsfor a more stable Taylor bubble, and therefore a better seal between thegas and the wall.

Bubbles raising with higher velocities are less efficient at clearingstagnant liquid from the wellbore. More specifically, bubbles raising athigher velocities presented a zig-zagging shape and a large tear at thetail. The shape of the bubbles raising with higher velocities isinefficient and facilitates the backflow of liquids along the liquidfilm surrounding the Taylor bubble and reduces the sweeping capacity orpiston effect of the Taylor bubble.

It can also be observed in FIG. 10 that the lower the Eo number, thehigher the Recovery Factor of the system. Inferring from these results,the lower the Eo number, the better the sweeping or piston effect of theTaylor bubble and increased transport of stagnant liquid from thewellbore. The best results are obtained when closer to the criticalEo=4.4, which yields a Recovery Factor of up to 76%. Accordingly, astable Taylor bubble improves the ability of the gas injected by thebacksweep lift 20 of the present invention to move liquid through thelift tube 38. In one embodiment, the systems and methods of the presentinvention are configured to form a Taylor bubble in the lift tube withan Eötvös number of approximately Eo=4. In one embodiment, the backsweeplift 20 of the present invention injects gas into the wellbore such thata Taylor bubble formed in the lift tube 38 has an Eötvös number ofbetween approximately 3.9 and approximately 4.7.

The backsweep lift of embodiments of the present invention provides manybenefits compared to known artificial lift systems and methods. Forexample, embodiments of the backsweep lift of the present invention canbe installed in a wellbore without removing existing tubing from thewellbore. Accordingly, the operational cost of the backsweep lift islower than known artificial lift systems. Moreover, the backsweep liftcan be installed quicker than known systems that require removal ofexisting tubing from the wellbore, decreasing the intervention time or“downtime” of the well required to install the backsweep lift. Further,the backsweep lift does not require installation of gas lift valves inthe vertical section of the wellbore. Additionally, the backsweep liftof the present disclosure injects a lower volume of gas into the wellcompared to other intermittent gas lift systems. The gas injected intothe well according to embodiments of the present invention does notcontact the geologic formation.

While various embodiments of the system have been described in detail,it is apparent that modifications and alterations of those embodimentswill occur to those skilled in the art. It is to be expressly understoodthat such modifications and alterations are within the scope and spiritof the present disclosure. Further, it is to be understood that thephraseology and terminology used herein is for the purposes ofdescription and should not be regarded as limiting. The use of“including,” “comprising,” or “having” and variations thereof herein aremeant to encompass the items listed thereafter and equivalents thereof,as well as, additional items.

The term “automatic” and variations thereof, as used herein, refers toany process or operation, which is typically continuous orsemi-continuous, done without material human input when the process oroperation is performed. However, a process or operation can beautomatic, even though performance of the process or operation usesmaterial or immaterial human input, if the input is received beforeperformance of the process or operation. Human input is deemed to bematerial if such input influences how the process or operation will beperformed. Human input that consents to the performance of the processor operation is not deemed to be “material.”

Aspects of the present disclosure may take the form of an embodimentthat is entirely hardware, an embodiment that is entirely software(including firmware, resident software, micro-code, etc.) or anembodiment combining software and hardware aspects that may allgenerally be referred to herein as a “circuit,” “module,” or “system.”Any combination of one or more computer-readable medium(s) may beutilized. The computer-readable medium may be a computer-readable signalmedium or a computer-readable storage medium.

A computer-readable storage medium may be, for example, but not limitedto, an electronic, magnetic, optical, electromagnetic, infrared, orsemiconductor system, apparatus, or device, or any suitable combinationof the foregoing. More specific examples (a non-exhaustive list) of thecomputer-readable storage medium would include the following: anelectrical connection having one or more wires, a portable computerdiskette, a hard disk, a random access memory (RAM), a read-only memory(ROM), an erasable programmable read-only memory (EPROM or Flashmemory), an optical fiber, a portable compact disc read-only memory(CD-ROM), an optical storage device, a magnetic storage device, or anysuitable combination of the foregoing. In the context of this document,a computer-readable storage medium may be any tangible medium that cancontain or store a program for use by or in connection with aninstruction execution system, apparatus, or device.

A computer-readable signal medium may include a propagated data signalwith computer-readable program code embodied therein, for example, inbaseband or as part of a carrier wave. Such a propagated signal may takeany of a variety of forms, including, but not limited to,electromagnetic, optical, or any suitable combination thereof. Acomputer-readable signal medium may be any computer-readable medium thatis not a computer-readable storage medium and that can communicate,propagate, or transport a program for use by or in connection with aninstruction execution system, apparatus, or device. Program codeembodied on a computer-readable medium may be transmitted using anyappropriate medium, including, but not limited to, wireless, wireline,optical fiber cable, RF, etc., or any suitable combination of theforegoing.

The terms “determine,” “calculate,” “compute,” and variations thereof,as used herein, are used interchangeably and include any type ofmethodology, process, mathematical operation or technique.

To provide additional background, context, and to further satisfy thewritten description requirements of 35 U.S.C. § 112, the followingreferences are incorporated by reference herein in their entireties:Moreiras et al., Unified Drift Velocity Closure Relationship for LargeBubbles Rising in Stagnant Viscous Fluids in Pipes, Journal of petroleumScience and Engineering, Vol. 124, pp. 359-366, December 2014 (availableat https://doi.org/10.1016/j.petrol.2014.09.006); Nickens et al., TheEffects of Surface Tension and Viscosity on the Rise Velocity of a LargeGas Bubble in a Closed, Vertical Liquid-Filled Tube, InternationalJournal of Multiphase Flow, Vol. 13, Issue 1, pp. 57-69,January-February 1987 (available athttps://doi.org/10.1016/0301-9322(87)90007-3); White et al., TheVelocity of Rise of Single Cylindrical Air Bubbles Through LiquidsContained in Vertical Tubes, Chemical Engineering Science, Volume 17,Issue 5, pp. 351-361, 1962 (available athttps://doi.org/10.1016/0009-2509(62)80036-0); and Zheng et al., CFDSimulations of Hydrodynamic Characteristics in a Gas-Liquid VerticalUpward Slug Flow, International Journal of Heat and Mass Transfer, Vol.50, Issues 21-22, pp. 4151-4165, October 2007 (available athttps://doi.org/10. 1016/j.ijheatmasstransfer.2007.02.041).

What is claimed is:
 1. An intermittent gas lift system to remove stagnant liquid from a wellbore of a hydrocarbon well, comprising: a downhole check valve interconnected to a lower end of a production tubing positioned within the wellbore; a lift tube positioned within the production tubing, wherein an annular space is formed between an exterior surface of the lift tube and an interior surface of the production tubing; and a gas inlet port interconnected to the production tubing at a wellhead portion of the hydrocarbon well, wherein gas injected through the gas inlet port travels down the annular space to a distal end of the lift tube in a horizontal section of the wellbore and then pushes liquid up the lift tube.
 2. The gas lift system of claim 1, wherein the distal end of the lift tube is spaced from the lower end of the production tubing.
 3. The gas lift system of claim 1, wherein the downhole check valve prevents fluid from flowing out of the lower end of the production tubing.
 4. The gas lift system of claim 3, wherein when gas is injected through the gas inlet port into the annular space, pressure in the lower portion of the production tubing increases and the downhole check valve closes to prohibit fluid from a hydrocarbon reservoir proximate to the lower end of the production tubing from flowing into the production tubing.
 5. The gas lift system of claim 3, wherein when the injection of gas through the gas inlet port into the annular space stops, pressure in the lower portion of the production tubing decreases and the downhole check valve opens to permit fluid from a hydrocarbon reservoir proximate to the lower end of production tubing to flow into the production tubing.
 6. The gas lift system of claim 1, further comprising a solution inlet port at the wellhead portion of the hydrocarbon well to inject a pretreatment solution into at least one of the annular space and production tubing.
 7. The gas lift system of claim 6, wherein the solution inlet port is connected to at least one of the production tubing and the lift tube.
 8. The gas lift system of claim 1, further comprising a control system operable to automatically start the injection of gas into the gas inlet port when the control system determines that data from a sensor indicates the well is not producing hydrocarbons at a predetermined rate.
 9. The gas lift system of claim 1, wherein the distal end of the lift tube is within the horizontal section of the wellbore.
 10. The gas lift system of claim 1, further comprising a multiphase flowmeter interconnected to the lift tube proximate to the wellhead.
 11. The gas lift system of claim 10, wherein the multiphase flowmeter is positioned between the wellhead portion and a three-phase separator.
 12. The gas lift system of claim 1, further comprising a pressure sensor positioned within a horizontal section of the production tubing.
 13. A method of removing stagnant liquid from a wellbore of a hydrocarbon well, comprising: receiving first data from a sensor; determining that the hydrocarbon well is not producing hydrocarbons at a predetermined rate; injecting a gas into an annular space formed between an interior surface of a production tubing positioned within the wellbore and an exterior surface of a lift tube positioned within the production tubing; receiving second data from the sensor indicating that liquid flowing in the lift tube at the surface includes some of the injected gas; and stopping the injection of gas into the annular space.
 14. The method of claim 13, wherein the first data received by the sensor includes one or more of a pressure measured proximate to a bottom hole location and a pressure or a flow rate of hydrocarbons from the wellbore measured at or near the surface.
 15. The method of claim 13, further comprising injecting a pretreatment solution into the wellbore through at least one of the production tubing and the lift tube.
 16. The method of claim 15, wherein the pretreatment solution is injected into at least one of the annular space and directly into the lift tube.
 17. The method of claim 13, further comprising interconnecting a downhole check valve to a lower end of the production tubing.
 18. The method of claim 13, further comprising positioning the lift tube within the production tubing.
 19. The method of claim 18, wherein a distal end of the lift tube is spaced upstream from a lower end of the production tubing.
 20. A non-transitory computer readable medium comprising a set of instructions stored thereon which, when executed by a processor of a control unit, cause the processor to execute a method of removing stagnant liquid from a wellbore of a hydrocarbon well, comprising: an instruction to receive first data from a sensor; an instruction to determine that the hydrocarbon well is not producing hydrocarbons at a predetermined rate; an instruction to inject a gas into an annular space formed between an interior surface of a production tubing positioned within the wellbore and an exterior surface of a lift tube positioned within the production tubing; an instruction to receive second data from the sensor indicating that liquid flowing in the lift tube at the surface includes some of the injected gas; and an instruction to stop the injection of gas into the annular space. 